Great. Thank you, Mr. Chairman.
Thank you to you and all committee members for this kind invitation and the opportunity to speak with you today. We very much welcome the chance to share the Talisman Energy success story and answer your questions on the energy sector in general.
My name is Reg Manhas. I'm vice-president of corporate affairs for Talisman Energy. I'm based in Calgary, Canada. My colleague today, Jim Fraser, is the senior vice-president for North American shale.
Before we go any further, I just want to let you know I won't be going through the advisories on our presentation this morning, so that's for all your reading pleasure at a later point.
Before I turn it over to Jim to address the specifics of shale gas, I'd like to just say a couple of things about Talisman's global footprint and our commitment to corporate social responsibility. Talisman Energy is a Canadian company headquartered in Calgary, with exploration activities in North America, Latin America, Asia, the Middle East, and Europe. We take great pride in being a Canadian company operating on the global stage.
Talisman is committed to the highest levels of corporate, ethical, and social responsibility. We have been recognized as a national and global leader in the area of corporate social responsibility. I personally was very proud to serve on the national advisory group during the Government of Canada round tables on corporate social responsibility a couple of years ago.
Talisman is a developer of oil and gas around the world, but I note that we are not involved in the oil sands projects. In fact, over the past few years, Talisman has made a strategic decision to focus its North American business on natural gas.
I'm now going to turn it over to Jim Fraser to speak specifically to our shale operations in Canada. Thank you.
Once again, it's my pleasure to be here as well.
I would refer you to the global map on the second page of your handout. As we've mentioned before, Talisman is a worldwide independent oil and gas producer. We have operations in the North Sea, Southeast Asia, and North America. That's where the focus of the rest of my prepared comments will be, on our North America portfolio.
In the last several years, we have transitioned from a conventional gas and oil player to a predominantly shale gas player due to its significant long-term growth potential and low-cost structure. We have four shale plays in North America, each at different stages in their evolution. I'll talk about those specifically in a moment.
The fourth part of our portfolio is our exploration that handles exploration worldwide.
Referring to the next page, Talisman has approximately 1.8 million net acres of leases of shale gas portfolio in North America that consists of the four plays. Within that acreage position, we have original gas in place of 238 trillion cubic feet of gas. Referring to the pie diagram on the right part of the page, our contingent resource is estimated at 57 trillion cubic feet of gas. To put that in context, Canada consumes about 3.5 tcf, or trillion cubic feet, of gas every year, so this contingent resource from Talisman alone has the potential to fuel the country for 16 years.
As I mentioned earlier, we have four plays. The first and most mature is the Marcellus shale in Pennsylvania. We've grown that resource from basically zero production to over 270 million cubic feet of gas production in the last two years. It is one of the best returning shale plays in North America.
Second most mature is in northeast British Columbia, the Montney shale. This is a play that's distinguished by the thickness of the shale. It's up to 1,400 feet of gas-charged shale, as compared with 250 feet in the Marcellus. The project in B.C. is about 12 to 18 months behind the Marcellus, but results to date have been encouraging. To date, we've only drilled about 35 wells, and that's the major key in unlocking this play. It's to getting our costs down.
Our most recent entry is the Eagle Ford play in south Texas, because of the liquids content of the shale.
The fourth part of our portfolio is in the Utica formation in Quebec, where we have a very large acreage position of about 760,000 net acres. But I must stress, it's very early days in Quebec exploration, as there has only been a handful of wells drilled in Quebec.
You might ask, why shale gas?
The next slide actually has seven points I'd like to address.
First, shale gas provides a sustainable, long-life resource base to North America. These wells will have lives as long as 50 years.
Second, it's scalable. These are very large accumulations, some as large as 100 miles in length. Total shale production in North America in the year 2000 was essentially zero. It has ramped up to 10 billion cubic feet per day in 2010, or 15% of North America natural gas production. Analysts expect that shale gas will grow to over 25 bcf per day by 2015 and will supply as much as 50% of the total North America production by the year 2020.
Third, shale gas is developed using proven technologies of horizontal drilling and advanced fracture stimulation.
Fourth, these resources are very predictable. There is little variance in well-to-well performance.
Fifth, shale gas has a reduced carbon footprint relative to competing fuels. It emits 40% less greenhouse gases than coal, 30% less than fuel oil, and 22% less than conventional gas resources.
Sixth, it is low cost relative to other opportunities. This is because there is less geologic risk in drilling the wells, and the drilling and completion process is repeated potentially thousands of times, resulting in operational efficiencies.
The last point is the liquids potential. Recent successes in liquids-rich areas have resulted in a shift to developing liquids-rich areas to take advantage of higher commodity prices.
My last slide illustrates some of Talisman's best practices that we utilize in the development of this resource.
First is what we call our good neighbour program. This is where we proactively address impacts of shale development and set clear behaviours for our staff and contractors.
Second is our secondary containment and our environmental protection. We recycle 100% of the water we use in developed plays like the Marcellus. We proactively list on our website all the chemicals we use in fracture stimulation.
The last bullet point is actually probably the most important. We focus on safe operations. It's a cornerstone of our company philosophy.
In conclusion, there is a tremendous opportunity for Canada to develop its natural resources in a sustainable, responsible manner, which furthers our energy security and returns dividends to Canadians.
Thank you, ladies and gentlemen. I appreciate the opportunity to be here today.
The Canadian Society for Unconventional Gas is a not-for-profit association, formed in 2002, with a focus on broadening the understanding of unconventional natural resources and the technology to develop those resources among industry, governments, regulators, and the public.
Canada is blessed with a vast natural gas resource. During the past decade our resource base has grown from 390 trillion cubic feet, or tcf—about 70 years of supply—to more than 700 trillion cubic feet.
These natural gas resources include gas in conventional reservoirs, primarily in western Canada; gas in Canada's far north and in the offshore; as well as in unconventional reservoirs: coal seams, tight sandstones, and shales. The primary change during the past 10 years has been the emergence of unconventional gas resources as a major part of Canada's natural gas resource portfolio.
While Canada's conventional natural gas resources are in decline and becoming increasingly costly to find and develop, technology has evolved and been adapted to unconventional reservoirs in response to declining conventional opportunities. With a resource base of 128 tcf to 343 tcf, Canada's shale resource will have an important role in our future natural gas supply mix.
While most currently identified shale gas resources are in western Canada, important and potentially very significant resources are being investigated in Ontario, Quebec, and the Maritimes. In addition, shale gas geological trends in many parts of Canada are currently poorly defined or understood, and we expect to see growth in the resource base in many parts of the country.
Technology has unlocked unconventional gas potential. We have experienced a dramatic evolution of horizontal drilling capability with the development of custom drilling rigs and supporting technologies, resulting in significant reductions in drilling costs. Multiple wells drilled from a single surface location can reduce cumulative surface disturbance by two-thirds or more compared to single well drilling approaches.
Hydraulic fracturing of reservoirs has been practised for 60 years. The evolution of those techniques to enable multi-stage fracturing in both vertical and horizontal wells has resulted in greatly enhanced production performance.
In addition, micro-seismic monitoring and other techniques have enabled an improved understanding of where fractures go and how they behave.
At this time, all shale gas evaluation and development activity is provincially regulated. There is no activity in areas of federal jurisdiction. Although regulations can vary somewhat from one province to another, the primary functions of health, safety, and environmental protection are always addressed.
In some places water management is a particular concern to many people. It is important to recognize that through various government departments in all jurisdictions, the use and disposal of water in natural gas development is regulated, including for shale gas development.
Standard practices for well construction are designed to protect groundwater. At shallow depths, where drinking water is found in aquifers, the first stage of well construction includes the installation of steel casing and pumping cement between that steel casing and the rock to isolate the aquifers before drilling deeper. Once the well has been drilled into the shale, a second steel liner or casing is installed, and again cement is pumped between the liner and the rock, this time isolating the producing shale from all overlying formations or rock units. This approach, isolating both aquifers and the producing zone, is a standard production practice in wells around the world.
When this construction stage is complete, hydraulic fracturing operations commence. It's important to recognize that the fracturing operation is not permitted to compromise the integrity of the well construction.
Hydraulic fracturing is a process of inducing fractures in reservoirs by pumping a fluid, often containing sand or a similar proppant, down a well and into a rock formation at a predetermined location. The fluid creates cracks or fractures, or opens existing fractures, and the proppant holds the fractures open. With multi-stage fracturing, the process is repeated a number of times in a single well. For horizontal shale wells, the process is repeated at various locations in the horizontal part of the well.
Many kinds of fluids can be used. Although some use no water, water-based fracs are common. For shales today we refer to these as slick-water fracs.
There is a widespread recognition within industry that the hydraulic fracturing process is water intensive, and producers and the service sector are working aggressively to reduce water use, employing strategies such as recycling and the use of non-potable or non-drinkable water.
Because hydraulic fracturing requires moving water and sand at high pressure, kilometres underground and into the shale, some compounds are often added to increase the capacity of the fluid to carry sand, to reduce the interaction of water with clay minerals, to improve flow characteristics, and to eliminate bacteria. These additives are regulated, primarily through federal programs and regulations, including worker training and certification requirements. We have identified several of those acts and programs and regulations for you.
There is no question that shale gas activity and development activities create concern, especially in areas that have little or no prior experience with oil and gas development. This is understandable. Shale gas evaluation and development, like any industrial activity, can be disruptive. Activity levels are high during drilling and fracturing operations but much lower once production is under way.
Shale gas development also brings economic activity and growth. In a July 2009 report, the Canadian Energy Research Institute estimated that every dollar of oil and gas expenditure generated $3 of impact on Canadian GDP. Most of that impact occurs in the jurisdiction of activity. Through economic development, employment, property sales, and income taxes, all levels of government benefit, from municipalities to the federal government.
In closing, shale gas will be an important part of Canada's future supply mix, and there are opportunities for development of the resource in many parts of the country. Shale gas development occurs within a comprehensive regulatory environment. Health, safety, and the environment, including the protection of surface and groundwater, are primary concerns. Although development can require large volumes of water, industry is working aggressively to address this concern.
Lastly, it's important to recognize that the benefits of shale gas development, including regional economic development and employment, will accrue to all levels of government.
Thank you, Mr. Chairman.
Good morning gentlemen.
Mr. Fraser, Talisman Energy is a company that is very involved in Quebec. Obviously through the current BAPE hearings we have witnessed broad opposition on the part of the Quebec public to shale gas extraction. Correct me if I am mistaken, but contrary to British Columbia, in Quebec this extraction takes place in densely populated areas and in agricultural areas, and our fear is that this will create few specialized jobs. Shale gas extraction is not necessarily a priority for Quebeckers because they prefer greener sources of energy and their needs are less pressing.
Obviously water use and environmental harm are particularly problematic for us. In fact, Talisman Energy violated the rules at the end of October because this summer the company used four million litres of water in order to hydraulically fracture its well at Gentilly. Out of those four million litres of water, three million were not treated and ended up in open reservoirs. That was of great concern to the public. We're told that there are about 30 wells, but imagine if there were 1,000, 10,000 or 15,000. That would be of great concern.
Is it your intention to do any research? Do you intend to improve the treatment of this waste water after fracturing? Do you intend to reduce the amounts of water? What do you want to do in order to reassure the public?
Absolutely, Mr. Chairman.
First, Ms. Brunelle, you're correct that there is a process now, the BAP process, which is ongoing. As a matter of fact, Talisman specifically has been very engaged in that process over the last month or so, and we understand it won't conclude until early February. Some of the issues you've brought up are being discussed in that format.
Specifically on water, everything we do is tightly regulated by the ministries of natural resources and environment in Quebec. So everything we do requires a permit. For example, we used surface water to fracture stimulate that well. We had permits to extract the amount of water we did. Conversely, we have permits from the MDDEP to take that water to a municipal treatment plant for disposal.
In the long term and on a large scale, if we hope to develop that resource, that is not what we would do with our water. There are two reasons for that. First, we try to reuse as much of that water as we can. In the example you cite, we will use that water again the next time we fracture stimulate a well, which won't be until next year. So we are keeping it, as you correctly cited, in an above-ground containment so that none of the water hits the ground. Our intent is to use that water the next time we fracture a well next spring. So reuse is a big part of our strategy.
The sewage treatment plants are not the solution for long-term treatment of water in Quebec. In other jurisdictions where there aren't very robust shale businesses, that isn't what happens. There are other technologies that exist today, such as reverse osmosis and evaporation, where this water is treated at scale. There have been two wells fracture stimulated in Quebec this year, so we are not at the scale yet to use those longer-term solutions. That's why we've used the sewage treatment plant.
But I'd like to be clear that everything we do is regulated by the MDDEP. We have permits from the MDDEP when we take that water to the disposal site. The sewage treatment plant also has to approve the treating of that water in their facility. So nothing that we've done is outside of current regulations. We really support a robust regulatory environment in Quebec, as well as any place else we operate.
And thank you to the witnesses for coming out this morning.
First of all, Mr. Chair, I'm very happy to see one thing, which is that the witnesses in this matter of our study, previous witnesses and today's witnesses, are very consistent on the issue of the contamination. They're basically consistently answering in the same manner as we heard before.
This summer, I was in Fort Mac and Dawson Creek on a visit, and I heard about the oil sands mining. I heard someone saying that it costs approximately $700 million to bring out the first drop of oil.
Anyone can answer my questions.
First, how long does it take to drill and actually produce shale gas? I heard that it costs $8 million or $20 million. Also, how does the cost of bringing shale gas to the market impact the price?
Good morning gentlemen. I apologize for being late; I may ask questions that you have already heard. On the other hand, I think sometimes it's important to repeat some questions, just to see if we get the same answer.
Some members: Oh, oh!
Hon. Denis Coderre: No, I'm just saying that.
Of course, there's an issue in Quebec; there is clearly a problem vis-à-vis our communication or perception, because it's a new issue. What I would suggest, because clearly the way that—and I'm not saying Talisman or any other—the industry tried to sell at the beginning, with Mr. Caillé and all the others, was a disaster, wasn't it?
You don't have to answer that, but it was a disaster. You're blushing; it's a good sign.
My concern is quality of life. I'm sure it's yours too. To ensure it, we need an independent way of monitoring. Of course, it is an issue of provincial jurisdiction, but we have a role to play. This is a serious study that we're doing, and I think we can all be part of the solution.
My concern is the science. We saw in Découverte on Sunday the issue with sodium, the issue of the use of water, the problem you had in Pennsylvania. So of course people are looking through some other examples. B.C. seems to be a model; we have some issues in other places.
How do you manage the issue of science? At the end of the day we can talk about the money, but if we talk about the wealth of people, I think the science and the monitoring process are the most important things. We need also to reassure people, because it's about their lives.
Regarding the possible contamination of water, vis-à-vis the way you use the water and when you bring it back, do you have any scientific study showing that what you're doing right now is great? And to help you, would it be a good thing—through NEB, through some expertise or environmental evaluation—to have in Canada an independent monitoring process whereby we can make a science study, with all the expertise from outside, and then put up a process to reassure everybody?
We now resume our meeting with our second panel. I would like to say, before I introduce the panel members who are here, either by video conference or in person, that Timothy Egan, president and chief executive officer of the Canadian Gas Association, cancelled out at the last minute due to some family issues. We may be able to get him at a later date. We'll certainly try for that.
We have by video conference from Calgary, from Encana Corporation, Richard Dunn, who is vice-president of the Canadian division, regulatory and government relations.
Welcome, Mr. Dunn.
We have, from the Department of Natural Resources, Marc D'Iorio, director general, director general's office; Denis Lavoie, research geoscientist, earth science sector, georesources and regional geology; and David Boerner, acting assistant deputy minister, Natural Resources Canada. Welcome to you.
We will start with Mr. Dunn by video conference.
Go ahead for up to seven minutes please, Mr. Dunn.
Let me say right from the get-go, I appreciate the opportunity to present by video conference. It is probably a lot nicer in Ottawa: I think it was minus 28 degrees this morning in Calgary.
As mentioned, I'm Richard Dunn, vice-president of government and regulatory relations for Encana Corporation. Just a quick blurb about Encana: we are the second-largest producer of natural gas in North America, with production of some 3.3 bcf a day, that's 3.3 billion cubic feet a day. That represents about 5% of North America's total production. We are 100% North American, with 40% of our production in Canada and some 60% in the United States, with a market capitalization of about $25 billion Canadian.
The natural gas industry in North America is undergoing a technological renaissance that will go down as one of the biggest game-changers in the history of Canadian energy. Technology has unlocked vast new supplies of natural gas, providing an abundance the like of which none of us has seen in our careers. As a result of the new and fast-advancing horizontal drilling and stimulation techniques, North American natural gas resources are now estimated to be in the range of 100 years to 150 years of supply at current production levels. This technology has unlocked world-class places such as the Horn River and Montney Basins in northeast B.C. It offers significant promise in new producing regions across the country, including Quebec and New Brunswick.
I can create a picture of what this technology in action looks like. I am talking about multiple horizontal wells from a single pad location, which is roughly 200 metres by 200 metres on the surface. This taps into some 13 square kilometres of reservoir buried thousands of metres deep and accesses tens of billions of cubic feet of natural gas. You can have several high-tech operations under way at the same time. In one well, a high-tech well log is being run; another well is being completed, with as many as 24 separate stimulations in the horizontal well bore; and still another well is being prepared for production.
We look forward to showing the committee a truly high-tech operation sometime in the near future.
Canada is at the forefront of this energy renaissance. It's also at the forefront of environmental and economic stewardship. Communities do not have to choose between the vast economic opportunities that natural gas offers and the protection of their environment. What allows us to achieve this balance? First, we make use of best practices in quality engineering design across the breadth of our operations. Second, we observe solid regulations, which oversee all aspects of our development. These regulations pertain to diverse areas such as drilling, water management, air emissions, wildlife impact, and worker health and safety. Protection of groundwater is highly regulated throughout all phases of our operations. Regulations are in place to deal with the storage of saline water, setbacks of producing wells from local water wells, and protection of aquifers. From a design perspective, we've heard that engineering steelcase systems, which are fully cemented externally, provide multiple barriers to the migration of fluids from well bores to groundwater aquifers.
In Canada, we support the disclosure of increased information regarding the composition of the frac fluids we use in hydraulic fracturing. However, we go further. We are working to ensure that, wherever possible, we use the most environmentally responsible hydraulic fracturing fluid formations and fluid management practices. The industry as a whole is pressing forward with reducing our environmental footprint by drilling many wells—up to 16 in the Horn River from a single pad—from the same location, recycling water where practicable, and searching for new sources of water that would not otherwise be used. As an example, together with our partner Apache, Encana recently invested more than $50 million in a plant that provides a water supply from deep saline aquifers. This otherwise unusable water, as salty as sea water, is a substitute for fresh surface water that would otherwise have been used for fracturing.
I'd like to turn to the economic impact of the industry and spend a few minutes on the huge economic benefits that our industry provides across the country, including jobs.
According to figures from the American Natural Gas Alliance, in 2008 natural gas supported more than 600,000 jobs across Canada and contributed more than $100 billion to Canada's GDP. The studies show that every Canadian province has natural-gas-related jobs, and spending in the west brings significant benefits to the rest of Canada. Approximately 15% of the economic benefits from the investment in natural gas in western Canada goes to other provinces, much of that to Ontario and Quebec. Encana's spend includes millions of dollars directed toward Ontario- and Quebec-based suppliers, from high-tech suppliers to consultants to manufacturers, including such companies as Hoerbiger, Quadra Chemicals, and Tenaris Steel. As well, the industry brings significant benefits to local service sectors where we operate. In B.C., for instance, even though the service sector is relatively immature, more than 50% of our spend is directed toward local service providers, including a significant amount with aboriginal-owned businesses.
However, with the marked increase in shale gas production in North America, the price of natural gas has dropped, responding to basic supply and demand. As well, it's expected that the natural gas commodity prices will be low for the foreseeable future. Canadian shale gas plays are facing great challenges to compete in the northeast U.S. markets that we once supplied handily. The simple fact is that with the development in North American shales, the U.S. does not need our product to the extent that it did. While we have tremendous resources, we also face some inherent disadvantages, such as increased costs from operating in a northern climate and long distances to transport our gas to market. Large shale gas supplies are being tapped in Pennsylvania and Michigan, near our traditional and core markets. In large part due to these competitive challenges, since 2008, Canadian production has decreased some 20%, while over the same period the United States production has increased some 20%.
What can we do about these competitive challenges? In the short term, industry continues to improve its efficiencies. Provincial governments as well have done an excellent job in creating a competitive environment. One important thing the federal government can do is to adopt the CAPP federal budget proposal that will temporarily level the playing field by proposing an equivalent tax treatment to that afforded in the U.S. to natural gas developers. This tax treatment is roughly equivalent to the current tax treatment afforded to manufacturers and processors in Canada.
In the longer term, the health of the industry will be dependent upon creating markets both domestically and abroad, expanding natural gas use as a means of addressing the pressing demands to reduce carbon emissions. Natural gas is the cleanest burning fossil fuel, and greenhouse gas benefits through natural gas displacing hydrocarbon fuels in industries such as transportation and power generation are significant, providing between a 20% to 50% reduction in greenhouse emissions per unit of energy. Increased use of natural gas will create jobs and more government revenue through taxation and royalties.
Additionally, to turn to foreign markets, in transitioning to a middle-class society, Asia represents the other major market opportunity for natural gas. China, for instance, is expected to quadruple its natural gas consumption by 2020. Asia is injecting billions of dollars into growing our natural gas industry to meet its own energy needs. As part of this, LNG facilities on the west coast and supporting pipeline infrastructure will be required to access this market opportunity.
In conclusion, the Canadian natural gas industry is a responsible, sustainable, well-regulated industry that is a major contributor to the Canadian economy, yet this industry is facing significant competitive challenges. To maintain and grow markets domestically and internationally, it requires access to foreign investment and export markets, support for strategic infrastructure programs, and bridging fiscal policies so we'll continue to ensure this industry does not become further marginalized.
Thank you, Mr. Chairman.
The goal of our presentation today is to provide you with a background, as you requested, on shale gas exploration and production in North America. We would like to give you an outline of the geoscience knowledge used to identify oil and gas potential, as well as a preliminary assessment of shale gas resources in Canada.
As you've probably heard abundantly over the last sessions here, shale gas has changed the North American energy market. You can look at the top diagram on page 3 at the NEB reference case as of July 2009, which now starts to include shale gas as part of their forecast and their scenarios going forward, which is new as of 2007--they were not including shale gas in these. As well, perhaps more strikingly, when you look at the North American natural gas supply, you can see that it peaked in 2000, after which the supply from the Gulf of Mexico had started declining, and from 2005 forward, it started moving up again due to the shale gas production in the U.S. In Canada, shale gas production is expected to have the same impact on the gas supply.
Production of shale gas in North America began in the United States some twenty years ago, in the Barnett shale.
Since 1990, nearly 12,000 wells have been drilled, and ultimate recoverable reserves are estimated at 30 tcf, or trillion cubic feet.
The most promising field in the U.S.A. is the Marcellus shale. It is very promising because the organic layer in that shale is very rich. Production there began in 2000, or 10 years ago, and 2000 wells have been drilled, with ultimate recoverable reserves in the Marcellus shale estimated at 49 tcf. To put that into context, North American demand for natural gas is approximately 25 tcf per year.
I'll turn to slide 5, the Canadian context. You've heard of the Horn River. Since 2006, this is the area that's being explored and is going into production. In terms of the potential resource that could be available, the Canadian Society for Unconventional Gas is estimating that approximately 500 tcf might be available from the Horn River Basin. As well, the Utica and Lorraine basins are now being looked at in Quebec and have a potential of 181 tcf. Shale gas potential exists in many other parts of the country as well, not just in these areas shown on the map--in Ontario, for example.
Again, putting these potential resources in context, the Canadian gas demand on a yearly basis as of 2008 was about 2.5 tcf.
Our role is to assess the geological context. The work done by the Geological Survey of Canada and Natural Resources Canada is published and funded by taxpayers. All the work conducted by the Geological Survey of Canada is published in scientific journals or publications produced by Natural Resources Canada.
The data and publications are used by the private sector, in the development of new exploration sites, and by the public sector, by regulatory officials and the provinces that own the resources.
Most shales currently being explored have been mapped or studied by the Geological Survey of Canada, which was founded in 1842.
Shales can be very different in terms of mineralogy. For example, the organic matter that actually determines its potential can vary, but there are also differences in silica and carbonate content that affect our ability to fracture the rock, in the case of natural gas production.
The key elements on this in the work that the Geological Survey does really have to do with the petroleum system and how you generate resources. To have a working petroleum system, you need sedimentary rock and you need several kilometres, typically, of sediment. You need a layer that's going to be very rich in organic material. That's the source rock, and it's typically clay and it becomes shale. So shales are the source rock for petroleum systems most of the time. Then you need to bury the system and expose it to some heat--we call it cooking--and you create petroleum from that. Eventually, you keep cooking it and you produce natural gas. If you keep cooking, well then everything is gone and it dissipates.
Eventually the oil and gas will migrate into a reservoir that is a structural trap. The structural traps are your conventional reservoirs. With the technology now, putting together the ability to fracture and to horizontally drill, you're able to go back to the source rock, which is the shale.
Slide 7 looks at the extent of the preliminary assessment of shale gas resources. The Geological Survey looked at what's available at the surface and also at the rocks, the drilling, and all the data that's available publicly, as well as the seismic records. In the typical cross-section, what you would look for is that source rock, which you see in red in the diagram on the left. That is the shale natural gas, and typically there's an impermeable layer on top that has trapped...left the natural gas where it is. These are obtained partly by the seismic profile, but then with analysis of the rocks and geochemical analysis to understand the system, its evolution with time, and then the potential of the rock itself.
In the second diagram--I think it's a diagram that's been shown already today--is your typical type of drilling, where you start vertically and then you go horizontally. Typically, in Canada the areas that are currently producing natural gas or where they're exploring for natural gas out of shales are several kilometres below the surface. Again, the context for groundwater is that groundwater is typically in the first few hundred metres, near the surface.
Slide 8 deals with the roles and responsibilities of the various governments and regulatory agencies. Regulation of onshore oil and gas drilling and production, including shale gas, falls primarily under provincial jurisdiction, as well as of the Yukon Territory. The federal regulatory role is limited to territories onshore and offshore, through the offshore boards, and, in the Northwestern Territories and Nunavut, through the National Energy Board.
The department of Natural Resources Canada, through the Geological Survey of Canada, plays a key role in understanding natural resource potential through its geoscience and geomapping programs.
Slide 9 is the last slide.
In the roles of responsibility of the federal government, other federal departments can be involved in the shale gas development, principally, Environment Canada, through their administration and enforcement of certain provisions of the Species at Risk Act or the Migratory Birds Convention Act; Environment and Health Canada, through the Canadian Environmental Protection Act and the chemicals management plan; Fisheries and Oceans, under the Fisheries Act, for the protection of fish and fish habitat; and finally, Indian and Northern Affairs Canada, through their responsibilities relating to oil and gas and their issuance of rights in the territories but not onshore Yukon.
Thank you, Mr. Chair.
Thank you for your help, colleague.
I have similar questions. We were told earlier that this fracturing—we know the fracturing technology, and actually Canada has done a fair bit with it in oil—has now been in use for some time. What do our government agencies know, and the industries as well, over a period of time, of these new technologies? We're hearing how the new technologies are now making a lot more available. I think the initial reaction of lay people is that these are kind of violent things that happen underneath the ground. Do we really have the studies to tell, over time, what the impact is of the induction of new chemicals and the use of water? If so, where are those studies?
We heard earlier reference to the EPA. First studies were in 1994; that sounds pretty recent. So I'm looking at the experienced studies we have, such as from the Canadian government, because the energy board does have a role in approvals of new projects. I'm not sure where that goes with gas, but certainly it has to do with the oil sands. But on these particular things, do we have the studies conducted? And if so, where can you point us?
There are two aspects to your question. The first one is the intensity of that fracturing event--how destructive it can be and how big it can be.
As Dr. Boerner was saying, the industry is putting seismographs in adjacent wells to record the earth movement at the time of fracturing. They are recording those values and expressing them in terms of the Richter scale, as for any other type of earthquake.
You may not know that on the Richter scale there are negative values; at the time they defined the Richter scale, the smallest earthquake they could register was given a zero value, but with more modern instruments we can go into negative values for smaller earthquakes. The intensities of those fracturing events are between -2 and -3 on the Richter scale, so these are very small seismic events that are recorded.
With reference to the permeability or the preservation of the water or the gas in the rock, in most of the shale gas rocks in Canada the gas was generated hundreds of millions of years ago, and it's still trapped in those rocks. That means that the geological system was fairly impermeable.
We have some other examples in Quebec, for example. There is an old gas field that has been exploited near Quebec City. It's called the Saint-Flavien gas field. That gas was generated by the Utica shale and has been trapped in that conventional reservoir, overlaid by the Utica and the Lorraine shale. The gas has been there for 450 million years. Those geological systems are very impermeable systems.
I really do apologize. I was visualizing the question.
Since the founding of the Geological Survey of Canada in 1842, this scientific body has produced basic geological data which is fundamental to understanding sedimentary basins in Canada. One of the research topics included in this fundamental geological data is an evaluation of hydrocarbon potential. That work included several studies on conventional systems. Bear in mind that the interest in shale gas is recent. For many years, the Geological Survey worked on hydrocarbons and conventional systems. The systems include parent rock, the rock from which hydrocarbons are produced. Today, we are looking at shale for shale gas. Shale produces hydrocarbons. We have taken a very close look at its characteristics: the thickness, the geographic distribution, the amount of organic material, the degree of thermal maturity, of heat exposure, to determine if the organic shale produced oil or gas. So a host of scientific data is available in the various publications by the Geological Survey of Canada, on the geological aspects of conventional hydrocarbons.
With shale gas, the parent rock, the rock which is the source of hydrocarbons, is also the reservoir. So we try to produce from this source rock. The data relating to this kind of work is the same as that which is used to evaluate conventional systems. We try to determine the amount of organic material, and the quantity of gas present in the rock. There has not been a specific study on shale gas rock, since we had already studied it as parent rock in conventional systems.
The Geological Survey synthesized the material and produced a preliminary assessment of shale potential in Canada in 2006. Tony Hamblin from the Geological Survey of Canada is the author of the report which is available to the public. I don't remember which issue it is, but I could send it to you. In recent years, this report has been one of the Geological Survey's leading publications, the one which has been most successful in bookstores, we are told. It has been downloaded many, many times. It covers current knowledge of shale gas in Canada.
A confusing point for me in trying to understand what the effect of a new industry is—and aquifers are at play in this question—is how we're doing the studies at the same time or after having drilled, in some places, many hundreds, if not thousands, of wells into those same areas as aquifers. Do you follow my concern?
One of the concerns of the public is that without baseline research, without a baseline understanding of what was there before an industrial project, it's impossible to consider what the effects of the project have been, because the company can say, “Well those conditions were pre-existing”, or “That contamination was naturally occurring”. We've seen this in the tar sands already, where they say, “The river already had those pollutants in it. It's not the operations of the oil companies.”
Do you see where the public might be confused why the federal government is doing this after all these plays have already been done?